System and method for carbon dioxide sequestration in offshore saline aquifers as carbon dioxide hydrate

ABSTRACT

A CO2 sequestration system sequesters carbon dioxide as carbon dioxide hydrate in offshore saline aquifers. The system includes an offshore aquifer in a tropical region. A plurality of wellbores are positioned inside or around a perimeter of the aquifer. The CO2 may be injected into the aquifer via separate injectors located in the wellbores connected to the aquifer while aquifer water or brine is produced from one or more of the other wellbores and provided to the aquifer. Injection of the CO2 into and production of water from the offshore aquifer at separately timed intervals may maintain the reservoir pressure below the reservoir fracture pressure and the hydrate formation pressure so that the CO2 may be stored as carbon dioxide hydrate within the aquifer. Depending on the specific output desired, the aquifer may be positioned either straddling or within a hydrate stability zone. A method for sequestering CO2 uses the aforementioned system to carry out CO2 sequestration.

FIELD OF THE INVENTION

The disclosure relates generally to carbon dioxide sequestration, andmore specifically to sequestering carbon dioxide as carbon dioxidehydrate in offshore saline aquifers.

BACKGROUND OF THE INVENTION

The Paris Agreement sets the long-term goal to limit global warming tobelow 2° C., preferably to 1.5° C. above pre-industrial times. CO₂ is agreenhouse gas, which is released from the combustion of fossil fuels.Capturing the emitted CO₂ and storing it permanently in a subsurfacereservoir, commonly known as carbon capture and storage (CCS), is animportant technology for reducing anthropogenic CO₂ emission. In someindustries, such as cement production, refineries, iron and steel, andpetrochemical, it is difficult to avoid the CO₂ emission without CCS.The first project to inject captured CO₂ into an aquifer for the purposeof storage was initiated in 1996.

The mechanisms of CO₂ storage in an aquifer include structural trapping,capillary trapping, solubility trapping, and mineralization. When CO₂ isinjected into a saline aquifer, CO₂ moves upwards because it is lighterthan the formation brine, except in an aquifer at ultradeep water depths(over 3,800 meters in tropical regions) with high pressure and lowtemperature where CO₂ is denser than the formation brine. Injected CO₂moves upward until it encounters an impermeable caprock. Structuraltrapping requires a confining caprock to avoid CO₂ leakage. Thistrapping efficiency is determined by the structure of the sedimentarybasin. Capillary trapping is caused by the movement of CO₂ and water.When injected CO₂ displaces the formation water, the CO₂ saturationincreases while water saturation decreases. As CO₂ migrates upward,water flows downward. The wetting phase (water) enters the poresoccupied by the nonwetting CO₂ phase. The CO₂ saturation changes causedby water displacement leads to CO₂ being trapped in the pores.Solubility trapping is caused by the solubility of CO₂ into the brine.Solubility depends on the water salinity, reservoir pressure, andtemperature. Although CO₂ dissolves quickly in water (which shares thesame pore space), dissolution occurs slowly by diffusion and convectiononce the pore space is CO₂ saturated. Therefore, complete dissolution ofinjected CO₂ into the formation brine can take a long time.Mineralization is caused by chemical reactions between the dissolved CO₂and the rock minerals. Dissolved CO₂ initiates geochemical reactionswith the formation rock leading to the formation of carbonate minerals.However, such geochemical reactions take place over hundreds of years orlonger.

CO₂ sequestration in saline aquifers has been investigated by reservoirsimulations. Homogenous and field scale models have been used toinvestigate CO₂ storage capacity in saline aquifers. The feasibility ofsequestering CO₂ as CO₂ hydrate in a saline aquifer has also beeninvestigated through experiments. CO₂ hydrate formation can act as theextra barrier to CO₂ migration. Pore level visualization of CO₂ hydrateformation has shown that a substantial amount of CO₂ hydrate can form ina water-saturated porous medium at certain pressures and temperatures.Both free CO₂ and CO₂ hydrate can co-exist in some pores because of theshortage of water within those pores. Different pore geometries andimpurities of CO₂ mixed with CH₄ and N₂ can affect the CO₂ hydrateformation in saline aquifers. Injecting CO₂ into a methane hydratereservoir to displace the methane has been studied by a number ofresearchers. The process has been previously piloted in Alaska, withresults revealing that the production rate is too slow forcommercialization.

Storing CO₂ as CO₂ hydrate in offshore aquifers has been proposed andstudied by a number of laboratory researchers. Results have shown thathydrate formation blocks the near wellbore pore space thus preventingfurther injection of CO₂. Consequently, it is generally believed thatCO₂ cannot be injected into the hydrate stability zone (or HSZ).

BRIEF SUMMARY OF THE INVENTION

The disclosed subject matter provides a system for sequestering carbondioxide as carbon dioxide clathrate in offshore saline aquifers. Thesystem includes an offshore aquifer in a tropical region. A plurality ofwellbores are positioned inside or around a perimeter of the aquifer.The CO₂ may be injected into the aquifer via separate injectors locatedin the wellbores connected to the aquifer while water is produced fromwellbores not used for CO₂ injection. Injection of CO₂ into andproduction of water (also known as brine) from the offshore aquifer atseparately timed intervals may maintain the reservoir pressure below thereservoir fracture pressure and the hydrate formation pressure so thatthe CO₂ may be stored as carbon dioxide hydrate within the aquifer.Depending on the specific output desired, the aquifer may be positionedeither within, or straddling a hydrate stability zone. A method forsequestering CO₂ uses the aforementioned system to carry out CO₂sequestration.

A method is further provided for sequestering carbon dioxide. The methodincludes identifying an offshore aquifer, typically but not exclusivelyin a tropical region, configured as a reservoir. Once the offshoreaquifer is identified, a plurality of wellbores are positioned inside oraround the perimeter of the offshore aquifer. CO₂ is then injected intothe aquifer through one or more wellbores while water is produced fromthe aquifer through the other wellbores. Water production may maintainthe reservoir pressure below the reservoir fracture pressure and thehydrate formation pressure. In certain embodiments, in order to get acertain amount of CO₂ stored, the offshore aquifer may be positionedeither inside of a hydrate stability zone or straddling a hydratestability zone.

BRIEF DESCRIPTION OF THE DRAWINGS

The disclosed subject matter, objectives, and advantages thereof, willbest be understood by reference to the following detailed description ofan illustrative embodiment when read in conjunction with theaccompanying drawings, wherein:

FIG. 1 displays a graphical presentation of a phase diagram of CO₂hydrate in accordance with embodiments.

FIG. 2 displays a graphical presentation of sea water temperature intropical regions in relation to water depth in accordance withembodiments.

FIG. 3 displays a graphical presentation of a CO₂ hydrate stability zonein an offshore sediment in accordance with embodiments.

FIG. 4 displays a graphical presentation of a hydrate stability zonethickness in relation to water depth in a tropical region in accordancewith embodiments.

FIG. 5 displays a graphical presentation of the density of CO₂ inrelation to depth in an offshore sediment in a tropical region inaccordance with embodiments.

FIG. 6 displays a graphical presentation of a relative permeabilitymodel in accordance with embodiments.

FIGS. 7A-D display temperature profiles (in ° C.) of an aquifer locatedoutside of a hydrate stability zone in accordance with embodiments. FIG.7A displays 1 injector (Phase 1: 2021-2026). FIG. 7B displays 1 injectorand 3 producers (Phase 2: 2026-2044). FIG. 7C displays 3 injectors and 1producer (Phase 2: 2044-2066). FIG. 7D displays 4 injectors (Phase 4:2066-2081).

FIG. 8A-C display temperature profiles (in ° C.) of an aquiferstraddling the hydrate stability zone in accordance with embodiments.FIG. 8A displays 1 injector and 3 producers (Phase 1: 2021-2105). FIG.8B displays 3 injectors and 1 producer (Phase 2: 2105-2202). FIG. 8Cdisplays 4 injectors (Phase 3: 2202-2221).

FIG. 9A-D display temperature profiles (in ° C.) of an aquifer locatedinside of the hydrate stability zone in accordance with embodiments.FIG. 9A displays 4 water producers (Phase 1: 2021-2022). FIG. 9Bdisplays 1 injector and 3 producers (Phase 2: 2022-2027). FIG. 9Cdisplays 3 injectors and 1 producer (Phase 3:2027-2166). FIG. 9Ddisplays 4 injectors (Phase 4: 2166-2185).

FIG. 10 displays a graphical presentation of simulation results of anaquifer outside of a hydrate stability zone injected with CO₂ and withwater production in accordance with embodiments.

FIG. 11 displays a graphical presentation of simulation results of anaquifer outside of a hydrate stability zone showing the saturation andpressure change during CO₂ injection in accordance with embodiments.

FIG. 12 displays cross-section view of an aquifer without a hydratestability zone (Case 1) showing fraction of pore volume occupied by CO₂hydrate at the end of Phase 4 in 2081.

FIG. 13 displays a graphical presentation of simulation results of anaquifer straddling a hydrate stability zone injected with CO₂ andincluding water production in accordance with embodiments.

FIG. 14 displays a graphical presentation of simulation results of anaquifer straddling a hydrate stability zone showing the percent of porevolume occupied by CO₂, water, and CO₂ hydrate in relation to pressurechange in accordance with embodiments.

FIG. 15 displays a cross-section view of an aquifer model straddling ahydrate stability zone (Case 2) showing the fraction of pore volumeoccupied by CO₂ hydrate at 2221.

FIG. 16 displays a graphical presentation of simulation results of anaquifer inside a hydrate stability zone comparing the injection rates,production rates, and reservoir pressure in accordance with embodiments.

FIG. 17 displays a graphical presentation of simulation results of anaquifer inside a hydrate stability zone and showing the percent of porevolume occupied by CO₂, water, and CO₂ hydrate in relation to pressurechange in accordance with embodiments.

FIG. 18 displays a cross-section view of an aquifer model inside of ahydrate stability zone (Case 3) showing the fraction of pore volumeoccupied by CO₂ hydrate at 2185.

FIG. 19 displays a graphical presentation of the ratio of cumulative CO₂stored in relation to water produced (Million tons/Million tons) formultiple aquifers in accordance with embodiments.

FIG. 20 displays a graphical presentation of the ratio of cumulative CO₂stored in relation to cumulative water produced (Megatons/Megatons) formultiple aquifers in accordance with embodiments.

FIG. 21 displays a cross-section view of an aquifer model outside of ahydrate stability zone (Case 1) at 2081 showing the CO₂ leakage througha caprock in the aquifer in accordance with embodiments. (Unit:fraction)

FIG. 22 displays a cross-section view of an aquifer model straddling ahydrate stability zone (Case 2) at 2221 showing the CO₂ leakage througha caprock in the aquifer with a permeability of 1,000 md in accordancewith embodiments. (Unit: fraction)

FIG. 23 displays a cross-section views of an aquifer model inside ahydrate stability zone (Case 3) at 2185 showing the CO₂ leakage througha caprock in the aquifer with a permeability of 0.1 md in accordancewith embodiments. (Unit: fraction)

FIG. 24 displays a cross-section views of an aquifer model inside thehydrate stability zone (Case 3) at 2185 showing the CO₂ leakage througha caprock in the aquifer with a permeability of 1 md in accordance withembodiments. (Unit: fraction).

DETAILED DESCRIPTION

Reference now should be made to the drawings, in which the samereference numbers are used throughout the different figures to designatethe same components.

It will be understood that, although the terms first, second, third,etc. may be used herein to describe various elements, these elementsshould not be limited by these terms. These terms are only used todistinguish one element from another element. Thus, a first elementdiscussed below could be termed a second element without departing fromthe teachings of the present disclosure.

The terminology used herein is for the purpose of describing particularembodiments only and is not intended to be limiting. As used herein, thesingular forms “a”, “an”, and “the” are intended to include the pluralforms as well, unless the context clearly indicates otherwise. It willbe further understood that the terms “comprises” and/or “comprising” or“includes” and/or “including” when used in this specification, specifythe presence of stated features, regions, integers, steps, operations,elements, and/or components, but do not preclude the presence oraddition of one or more other features, regions, integers, steps,operations, elements, components, and/or groups thereof.

CO₂ Hydrate Stability Zone (HSZ)

At low temperatures and high pressures, CO₂ interacts with water to formsolid CO₂ hydrate, which is a crystal made up of water and CO₂ moleculeswith a formula of CO₂·nH2O (n≥5.75). FIG. 1 shows the phase diagram ofCO₂ hydrate. The hydrate exists below 15° C. over a range of pressures.Below 10° C., the equilibrium pressure of hydrate increases graduallywith temperature. However, above 10° C., it increases very rapidly withtemperature. Within the CO₂ hydrate phase boundary, solid CO₂ hydratecan coexist with liquid water and either gaseous CO₂ or liquid CO₂depending on the temperature and pressure.

In the disclosed embodiments, environmental parameters consideredinclude tropical regions having an ocean surface temperature between 20°C. and 25° C.; a temperature profile is shown in FIG. 2 . The sea watertemperature drops rapidly in the thermocline region to around 5° C. at a1,000 meter water depth. The temperature then slowly decreases withwater depth to several degrees Centigrade.

According to FIG. 1 , when the water depth exceeds a critical value, thetemperature and pressure in the sediment below the seafloor fall withinthe CO₂ hydrate phase diagram and a HSZ exists. The thickness of the HSZis shown graphically in FIG. 3 . In order to calculate the thickness,the pressure versus temperature phase boundary curve of the CO₂ hydrate(FIG. 1 ) is converted to a depth versus temperature curve using theseawater hydrostatic gradient. The seawater temperature profile (FIG. 2) is then plotted along with the boundary curve. From a seafloor line, aline is drawn representing the geothermal gradient. The thickness of thehydrate stability zone may be identified as the distance between theseafloor and the intersection of the geothermal gradient with the CO₂phase boundary, as shown in FIG. 3 . It is noted that a geothermalgradient of 30° C./km and a seawater gradient of 10.52 kPa/m (0.465psi/ft) are utilized, which are common parameters associated with theGulf of Mexico.

FIG. 4 displays the HSZ at various water depths for a tropical region.It is shown that a HSZ starts to form at a water depth of 630 meters andits thickness increases to about 450 meters at a water depth of 5,000meters. The existence of a HSZ is a first of two conditions that need tobe met for the existence of CO₂ hydrate. The other condition is theexistence of a water-bearing porous sediment (or aquifer), whichprovides the water and the pore space for storage of CO₂ hydrate. If CO₂is injected into an aquifer within the HSZ, it eventually comes toequilibrium with the aquifer temperature and pressure and forms solidCO₂-hydrate which ends up blocking the near wellbore region, thusreducing the CO₂ injectivity. Consequently, it is generally believedthat injection of CO₂ into the HSZ is not possible.

In a tropical region, at a water depth of 3,800 meters and deeper,liquid CO₂ is denser than formation brine. Above this water depth, anegative buoyancy zone (NBZ) exists, as shown in FIG. 4 . If CO₂ isinjected into an aquifer at a depth shallower than the NBZ, it will sinkuntil it reaches the bottom of the NBZ where it will be neutrallybuoyant. If CO₂ is injected deeper than the NBZ, it will rise until itreaches the bottom of the NBZ. Therefore, the existence of a NBZguarantees that injected CO₂ will not rise to the seafloor; it acts as abarrier to post-injection CO₂ migration. As shown, the thickness of theNBZ increases with water depth. At a water depth of 4,700 m, the NBZ andthe HSZ have the same thickness. At water depth deeper than this, theNBZ is thicker than the HSZ. However, injection of CO₂ into an aquiferat such a water depth may be considered impractical due to the high costof ultradeep water wells. Therefore, water depths where a NBZ does notexist are analyzed.

Barriers to Post Injection Upward CO₂ Migration

For subsurface storage of CO₂, it is important to determine the numberof barriers to upward CO₂ migration subsequent to injection to ensurethat the injected CO₂ does not leak to shallower zones and eventually tothe seafloor. Depending on water depth and buried depth, there can be upto three independent barriers to upward CO₂ migration. The first andprimary barrier to upward CO₂ migration is the confining overburden ofan aquifer (usually formed of mudstone, siltstone, or shale) having verylow porosity and permeability. This barrier exists for confined aquifersat all water depths. The second barrier to upward CO₂ migration is theHSZ for aquifers having a water depth of 630 meters or deeper. If CO₂breaches the aquifer overburden and migrates to the HSZ, the formationof solid CO₂ hydrate will prevent further upward migration. For aquiferswith a water depth exceeding 3,800 meters, the NBZ forms a third barrierto upward CO₂ migration. The existence of the HSZ (at water depthslarger than 630 meters) and NBZ (at water depths larger than 3,800meters) creates additional barriers (besides the aquifer) to upward CO₂migration, which is beneficial for permanent CO₂ storage.

Hitherto, storage of CO₂ in offshore saline aquifers is mostly limitedto shallow water aquifers with a water depth below around 600 meters. Intropical regions, aquifers with such a water depth do not have a HSZ, asdepicted in FIG. 4 . In these areas, CO₂ migration may be monitored byacoustic tomography, 4D seismic, or other techniques in order to detectCO₂ leakage.

The disclosure presents the feasibility of storing CO₂ in a tropicalregion as CO₂ hydrate within the HSZ in an offshore aquifer. Two majoradvantages are associated with this scenario. First, if CO₂ can bestored as solid CO₂ hydrate, it becomes immobilized and the risk ofleakage may be substantially reduced. In fact, immobilizing CO₂ as CO₂hydrate serves as an additional barrier to post-injection CO₂ migration.Second, aquifers at deeper water depths and shallow buried depths may beable to store more CO₂ than aquifers at shallow water depths and deeperburied depths due to a higher CO₂ density. FIG. 5 gives the density ofCO₂ at various water depths and buried depths in a tropical regionassuming a seawater temperature given by FIG. 2 , a seawater hydrostaticgradient of 10.52 kPa/m, and a geothermal gradient of 30° C./km. It canbe seen that at a water depth of 500 meters and higher and shallowburied depth of less than 500 mbsf (meters below seafloor), CO₂ existsin liquid form with a density of 800 kg/m3 or higher. On the other hand,at a water depth below 300 meters and a buried depth of 800 mbsf anddeeper, although CO₂ exists in supercritical form, its density is lessthan 600 kg/m3. Due to the higher density of CO₂ within the HSZ thanoutside, more CO₂ may be stored within the HSZ than outside of the HSZ.

Reservoir Simulation

Three aquifer models (Cases 1 to 3) have been built to study offshoreCO₂ storage in a tropical region using the CMG-STARS simulator (of theComputer Modelling Group Ltd.). The simulator calculates the mass,momentum, and energy balances for the water, CO₂, CO₂ hydrate, and rockphases. When water and CO₂ combine to form CO₂ hydrate, CO₂ is in thesolid phase. In the model, phase saturation may refer to CO₂ in thenon-solid phase. The volume of CO₂ hydrate is given by the percent oforiginal pore volume occupied. In FIG. 4 , the three cases are shown asC1, C2, and C3. Case 1 is a shallow water (water depth of 300 m, caprockat 800 mbsf) aquifer without a HSZ. It is used as a reference case forcomparison. Case 2 is a deepwater aquifer (water depth of 800 m, caprockat 40 mbsf) straddling the HSZ (60% within HSZ, 40% below). Case 3 is adeepwater aquifer (water depth of 800 m, caprock at seafloor) within theHSZ.

Reservoir parameters are given in Table 1 below. The aquifer includesseven layers including a 30 meter thick, low permeability caprock as thetop layer. Below the caprock is a 50 meter thick reservoir consisting ofthe second to sixth layers. Below the reservoir is a 10 meter thickunderburden consisting of the seventh layer. For the aquifer thatstraddles the HSZ, the first to fourth layers are positioned inside theHSZ. The fifth to seventh layers are positioned outside the HSZ. For theaquifer within the HSZ, all seven layers are positioned inside the HSZ.The aquifer comprises an area of 23,240 acres (9.7 km×9.7 km), apermeability of 3,000 md, and a porosity of 30%. The caprock andunderburden comprise a permeability of 1×10⁻⁵ md and a porosity of 1%.In some embodiments and/or in some instances, the caprock andunderburden might not be considered as targets for the CO₂ storage.However, potential CO₂ leakage through the caprock and underburden isanalyzed. The ratio of horizontal to vertical permeability is assumed tobe 1. The reservoir temperature and/or pressure are controlled by thegeothermal and hydrostatic gradient, respectively. Initially, thereservoir is fully water saturated.

TABLE 1 Reservoir properties in various simulation cases Cases Case 1Case 2 Case 3 Reservoir properties Aquifer straddling HSZ Aquiferoutside 60% within HSZ, 40% Aquifer inside HSZ below HSZ Reservoirdimension (km²) 9.7 × 9.7 9.7 × 9.7 9.7 × 9.7 Water depth (m) 300 800800 Top of the caprock (mbsf) 800 40 0 Caprock thickness (m) 30 30 30Aquifer thickness (m) 50 50 50 Base thickness (m) 10 10 10 Cap and basepermeability (md) 1 × 10⁻⁵ 1 × 10⁻⁵ 1 × 10⁻⁵ Aquifer permeability (md)3,000 3,000 3,000 Cap and base porosity (%) 1 1 1 Aquifer porosity (%)30 30 30 Initial reservoir pressure (MPa) 11.6 8.8 8.4 Initial reservoirtemperature (° C.) 45.9 9.4 8.2 Reservoir heat capacity 2.6 × 10⁶ 2.6 ×10⁶ 2.6 × 10⁶ (J/m³ · ° C.) CO₂ hydrate heat capacity 203.7 203.7 203.7(J/g mol · ° C.) Rock thermal conductivity 2.47 × 10⁵ 2.47 × 10⁵ 2.47 ×10⁵ (J/m · d · ° C.) CO₂ hydrate thermal conductivity 3.4 × 10⁴ 3.4 ×10⁴ 3.4 × 10⁴ (J/m · d · ° C.) Water thermal conductivity 5.53 × 10⁴5.53 × 10⁴ 5.53 × 10⁴ (J/m · d · ° C.) CO₂ thermal conductivity 2.93 ×10³ 2.93 × 10³ 2.93 × 10³ (J/m · d · ° C.)

The water and gas relative permeabilities, shown in FIG. 6 , arecharacterized by the generalized Corey correlations. The parameters usedin the reservoir simulation are given in Table 2.

TABLE 2 Parameters in the generalized Corey correlations in relativepermeability Generalized Corey Correlation S_(gc) 0 S_(iw) 0.1 n_(g) 3n_(w) 7 k_(rgcw) 1 k_(rwgc) 1

For the aquifer straddling or inside the HSZ, CO₂ hydrate formation isgoverned by the following reactions:CO₂+6H₂O→CO₂·6H₂OH₂O+CO₂·6H₂O→7H₂O+CO₂

CO₂ hydrate properties are given in Table 3.

TABLE 3 CO₂ hydrate properties CO₂ hydrate properties Value Hydrationnumber 6 Enthalpy for formation and dissociation (kJ/mole) 60 Massdensity (kg/m³) 1,100 Structure I CO₂ hydrate molar density (mole/m³)7,458

For aquifers without or straddling the HSZ, it is important for thereservoir pressure to be kept below the fracture pressure of thereservoir in order to avoid CO₂ leakage. The simulation may stop whenthe fracture pressure is reached. The fracture pressure may becalculated by the Eaton's method equations:

$\sigma_{fp} = {{\frac{v}{1 - v}( {\sigma_{ob} - \sigma_{P}} )} + \sigma_{P}}$σ_(ob)=σ_(w) h _(w)+σ_(b) h _(b)σ_(p)=σ_(w)(h _(w) +h _(b))

where σ_(fp) is the fracture pressure gradient in kPa/m. v is thePoisson's ratio which is assumed to be 0.25 for sandstone, 0.4 for shalein the caprock and underburden. σ_(ob) is the overburden pressuregradient in kPa/m. σ_(p) is the pore pressure gradient in kPa/m. σ_(w)is the seawater pressure gradient and is assumed to be 10.52 kPa/m forseawater. h_(w) is the water depth in m. σ_(b) is the rock pressuregradient which is assumed to be 24.88 kPa/m for sandstone. h_(b) is theburied depth below the seabed for the sandstone reservoirs in meters.

The CO₂ flow rate and water availability are important parameters forCO₂ hydrate formation. As disclosed, the formation of CO₂ hydrate may becontrolled via reservoir pressure management by deliberate waterproduction and CO₂ injection through wellbores. As shown in FIGS. 7-9 ,each aquifer model is bound by four injectors each located in wellborespositioned at the corners of each aquifer model.

The initial temperature of the aquifer models is given in FIGS. 7-9 .Lower temperatures may exist at the lower ends of each aquifer modelwhile higher temperature may exist at the upper ends of each aquifermodel. Each aquifer model comprises 7,623 grids covering the area of23,240 acres. Each grid block includes a dimension of 294 meters in thex-direction and 294 meters in the y-direction. Each aquifer containsfour corner wells. In the z-direction, seven layers are presented. Thefirst layer comprises a 30 meter thick caprock. The second to sixthlayers, each 10 meters thick, comprise the reservoir. The seventh layer,a 10 meter thick layer, comprises the baserock. Simulations start atJan. 1, 2021 (2021-01-01) for all three models.

Case 1—Aquifer without a HSZ (FIGS. 7A-7D)

In Phase 1 covering five years from 2021 to 2026, a single CO₂ injectorexists in one corner of the aquifer model (Injector 1) injecting at 2000t/d or 0.73 Mtpa (FIG. 7A). Phase 1 may end when the reservoir pressureat the top layer in the aquifer reaches the fracture pressure (15.9 MPa)in 2026. In Phase 2, covering 18 years from 2026 to 2044, three waterproducers (Injectors 2-4) are added to three additional corners of theaquifer model, thus giving one CO₂ injector and three water producersproducing at 6,000 t/d in order to reduce the reservoir pressure (FIG.7B). Phase 2 may end when CO₂ breaks through in water producer-2 andwater producer-3 in 2044. In Phase 3, covering 22 years from 2044 to2066, water producer-2 and water producer-3 are converted into CO₂injector-2 and CO₂ injector-3 thus giving three CO₂ injectors injectingat 3,000 t/d (1.1 Mtpa) and one water producer producing at 5,000 t/d(FIG. 7C). Phase 3 ends when CO₂ breaks through in water producer-4 in2006. In Phase 4, covering 15 years from 2066 to 2081, water producer-4is converted into CO₂ injector-4 thus giving four CO₂ injectorsinjecting at 4,000 t/d or 1.5 Mtpa (FIG. 7D). The simulation stops whenthe reservoir pressure in the top reservoir layer reaches the fracturepressure of 15.9 MPa. The whole project may last 60 years.

Case 2—Aquifer Straddling the HSZ (FIG. 8 )

In Phase 1, covering 84 years from 2021 to 2105, CO₂ injector-1 existsin one corner of the aquifer model injecting CO₂ at 2,000 t/d (0.73Mtpa); water producer-2, water producer-3, and water producer-4 exist atthe other three corners of the aquifer model each producing water at2,500 t/d (FIG. 8A). Phase 1 ends when CO₂ breaks through in waterproducer-2 and water producer-3 in 2105. In Phase 2, covering 97 yearsfrom 2105 to 2202, water producer-2 and water producer-3 are convertedinto CO₂ injector-2 and CO₂ injector-3, thus giving three CO₂ injectorswith a total CO₂ injection rate of 3,000 t/d (1.1 Mtpa) and one producerproducing water at 2,500 t/d (FIG. 8B). Phase 2 ends when CO₂ breaksthrough water producer-4 in 2202. In Phase 3, covering 19 years from2202 to 2221, water producer-4 is converted to CO₂ injector-4 to givefour injectors injecting CO₂ at a total rate of 4,000 t/d or 1.5 Mtpa(FIG. 8C). The simulation stops when the pressure in the top reservoirlayer reaches the fracture pressure of 9.5 MPa. The whole project maylast 200 years.

Case 3—Aquifer within the HSZ (FIG. 9 )

In Phase 1, covering one year from 2021 and 2022, all four corner waterproducers produce a total water rate of 20,000 t/d and a bottomholepressure of 1.38 MPa (200 psi) (FIG. 9A). This phase ends when thereservoir pressure drops below 4 MPa in 2022 which is the CO₂ hydrateformation pressure corresponding to the second layer having atemperature of 8.2° C. (FIG. 1 ). In Phase 2, covering five years from2022 and 2027, water producer-1 is converted to CO₂ injector-1 to giveone injector injecting CO₂ at 2,000 t/d (0.73 Mtpa) and three waterproducers producing at a maximum rate of 15,000 t/d (FIG. 9B). Phase 2ends when CO₂ breaks through in water producer-2 and water producer-3 in2027. In Phase 3, covering 2027 to 2166, water producer-2 and waterproducer-3 are converted to CO₂ injectors to give three CO₂ injectorswith a maximum injection rate of 2,000 t/d (1.1 Mtpa) and one waterproducer with a maximum rate limit of 5,000 t/d (FIG. 9C). Phase 3 endswhen CO₂ breaks through in water producer-4. In Phase 4, covering 2166to 2185 (FIG. 9D), water producer-4 is converted to CO₂ injector-4 togive four CO₂ injectors with a maximum CO₂ injection rate of 4,000 t/d(1.5 Mtpa). Phase 4 ends when the reservoir pressure reaches 5 MPa whichis the CO₂ hydrate formation pressure corresponding to the bottom(sixth) reservoir layer having a temperature of 9.7° C. (FIG. 1 ). Thewhole project may last 164 years.

In embodiments, all wells are perforated throughout the aquifer (secondthrough sixth layers). The wellbore constraints in different phases forthe three cases are provided in Table 4. It is noted that the CO₂injection temperature is set at 15° C. for all three cases.

The simulations may compare CO₂ storage with and without CO₂ hydrateformation. It is noted that the solubility of CO₂ in the water phase andreactions between dissolved CO₂ with reservoir rock are not consideredas they usually take a very long time to come to completion.

TABLE 4 Simulation cases and well constraints Cases Case 1 Case 2 Case 3Well constraints Aquifer outside HSZ Aquifer straddling HSZ Aquiferinside HSZ Phase 1 2021-2026 (5 yr) 2021-2105 (84 yr) 2021-2022 (1 yr)Injectors 1 1 0 Producers 0 3 4 Injector pressure (MPa) 15.9 9.8 CO₂injection rate (t/d) 2,000 2,000 Producer pressure (MPa) 1.38 1.38 Totalwater production rate (t/d) 2,500 20,000 End of the phase Pressure =15.9 MPa CO₂ breakthrough Pressure = 4 MPa Phase 2 2026-2044 (18 yr)2105-2202 (97 yr) 2022-2027 (5 yr) Injectors 1 3 1 Producers 3 1 3Injector pressure (MPa) 15.9 9.8 8.9 CO₂ injection rate (t/d) 2,0003,000 2,000 Producer pressure (MPa) 1.38 1.38 1.38 Total waterproduction rate (t/d) 6,000 2,500 15,000 End of the phase CO₂breakthrough CO₂ breakthrough CO₂ breakthrough Phase 3 2044-2066 (22 yr)2202-2221 (19 yr) 2027-2166 (139 yr) Injectors 3 4 3 Producers 1 0 1Injector pressure (MPa) 15.9 9.8 8.9 CO₂ injection rate (t/d) 3,0004,000 3,000 Producer pressure (MPa) 1.38 1.38 Total water productionrate (t/d) 5,000 5,000 End of the phase CO₂ breakthrough Pressure = 9.8MPa CO₂ breakthrough Phase 4 2066-2081 (15 yr) 2166-2185 (19 yr)Injectors 4 4 Producers 0 0 Injector pressure (MPa) 16 8.9 CO₂ injectionrate (t/d) 4,000 4,000 End of the phase Pressure = 15.9 MPa Pressure = 5MPa Injected CO₂ temperature (° C.) 15 15 15 Total number of years 60200 164

Simulation results for Case 1 are shown in FIGS. 10 and 11 . As seen inFIG. 10 , the reservoir pressure increases when CO₂ is injected in Phase1 (2021-2026). As seen in FIG. 11 , the CO₂ saturation increases whilethe water saturation decreases. Phase 2 (2026-2044) begins when thereservoir pressure reaches the fracture pressure of the reservoir. Oncethe water production starts, the reservoir pressure decreases. When theCO₂ breaks through in producer-2 and producer-3, they are converted toCO₂ injectors to prevent recycling of CO₂ from the injectors toproducers. In Phase 3 (2044-2066), there are three CO₂ injectors; asmore CO₂ is injected and less water is produced, the pressure starts torise. The CO₂ breaks through water producer-4 in 2066 and it isconverted to a CO₂ injector. Continuous CO₂ injection in Phase 4(2066-2081) raises the reservoir pressure until the fracture pressure isreached in 2081. The water saturation continuously decreases during CO₂injection over 60 years (see FIG. 11 ). The CO₂ saturation increases upto 6% of PV in 2081 when the project is planned to be terminated. Thisresult is consistent with other works on CO₂ storage in aquifers, withan efficiency factor ranging from 1-6% PV.

The CO₂ hydrate saturation in the cross-section of the aquifer model ofCase 1 from Injector 2 to Injector 4 (FIGS. 7A-7D) in 2081 is shown inFIG. 12 . It is noted that there is no CO₂ hydrate formation at the endof Phase 4 in 2081.

In Phase 1, the simulation begins in 2021 with the aquifer fullysaturated with water; there is no CO₂ in the aquifer initially. When thereservoir pressure reaches the reservoir fracture pressure in 2026, 3.65Mt (Million tons) of CO₂ has been injected into the aquifer, whichamounts to 0.4% PV. In Phase 2, three water producers are added into thesimulation in 2026 in order to reduce the reservoir pressure. Theinjected CO₂ may occupy only a small part of the aquifer and may staymostly around CO₂ injector-1; there is no CO₂ seen in the cross-sectionfrom producer-2 to producer-4 (FIG. 7B). In Phase 3, when CO₂ starts tobreak through in water producer-2 and water producer-3, they areconverted to CO₂ injectors in 2044. In Phase 4, when the injected CO₂starts to break through in water producer-4, it is converted to waterinjector-4 in 2066. When the reservoir pressure reaches the reservoirfracture pressure, the project is terminated in 2081. There is no CO₂hydrate formed in 2081 is shown in FIG. 12 . The injected CO₂ only staysin the top layer of the aquifer because of gravity segregation.

For an aquifer straddling the HSZ corresponding to Case 2, CO₂ can becontinuously injected into the fifth and sixth layers because they areoutside the HSZ. The simulation results are shown in FIG. 13 . In Phase1 (2021-2105), CO₂ is injected at a constant rate of 2,000 t/d (0.73Mtpa) while the three producers produce water a total rate of 2,500 t/d;the reservoir pressure decreases with time. CO₂ hydrate forms around CO₂injector-1 once the CO₂ injection starts (FIG. 14 ) and delays CO₂transport in the aquifer. The CO₂ front breaks through in waterproducer-2 and water producer-3 in 2105, after 84 years of CO₂injection. At that time Phase 2 begins. Water producers 2 and 3 areconverted into injectors to give three CO₂ injectors and one waterproducer (FIG. 8B). The total CO₂ injection rate increases to 3,000 t/d(1.1 Mtpa) for three injectors and the water production rate remains at2,500 t/d. The reservoir pressure starts to rise in 2105. The injectorbottomhole pressure constraint limits the CO₂ injectivity in 2158. TheCO₂ injection rate is equal to the water production rate in 2158. Thereservoir pressure increases very little between 2158 and 2202. Once CO₂breaks through in water producer-4 in 2202, it is converted into CO₂injector-4 to give four CO₂ injectors (FIG. 8C). The total CO₂ injectionrate constraint is set to 4,000 t/d (1.5 Mtpa) for four injectors andthere is no more water production. However, the CO₂ injectivity islimited by the injector bottomhole pressure to a rate of 1,000 t/d (0.37Mtpa) for four wells. In Phase 3, the reservoir pressure increasesrapidly between 2202 to 2210 and then slowly between 2210 and 2221.Between 2202 to 2210, the pressure rises because of continuous CO₂injection with no water production. Most of the CO₂ is injected frominjector 1 where there is no free water and therefore no CO₂-hydrate isformed (see FIG. 14 ). Between 2210 and 2221, free CO₂ travels frominjector 1 to injector 4 where there is water; the water reacts with CO₂to form CO₂ hydrate. The rate of pressure increase becomes very slow dueto the 12% volume shrinkage during formation of CO₂ hydrate at reservoirconditions (Table 5). The reduced speed of pressure rise caused by CO₂hydrate formation is consistent with those observed in other literature.When the reservoir pressure reaches the reservoir fracture pressure of9.8 MPa in 2221, the projected is terminated. The simulation may last200 years and the cumulative CO₂ injected is 164 Mt.

TABLE 5 Volume changes during CO₂ hydrate reactions Volume at Volume atstandard reservoir conditions condition Components Mole (m³) (m³) CO₂ 12.24 × 10⁻² 0.45 × 10⁻⁴ H₂O 6 1.08 × 10⁻⁴ 1.08 × 10⁻⁴ CO₂ hydrate 1 1.34× 10⁻⁴ 1.34 × 10⁻⁴

As shown in FIG. 15 , a cross-section shows fraction of PV occupied byCO₂ hydrate from injector-2 to injector-4 (FIG. 8C) at 2221. The darkcolor indicates that very few CO₂ hydrate occupies the PV while thewhite color indicates that most PV is filled with CO₂ hydrate. BecauseCO₂ hydrate is in a solid state, liquid CO₂ and water only account forthe PV not occupied by the solid CO₂ hydrate. In Phase 1, the simulationstarts in 2021 and the aquifer is fully saturated with water initially.The injected CO₂ reacts with water near the injector-1 to form CO₂hydrate immediately in the second to fourth layers and reduces CO₂injection into them. However, CO₂ may be injected into the fifth andsixth layers. CO₂ is injected from injector-1 between 2021 and 2105.Water production from producer-2, producer-3, and producer-4 reducesreservoir pressure. No CO₂ hydrate is seen in the cross-section fromproducer-2 to producer-4 because the CO₂ has not reached them. Phase 1lasts 84 years because CO₂ hydrate formation reduces the CO₂ transportin the aquifer and delays the CO₂ breakthrough at the producers.Producer-2 and producer-3 are converted to injectors when CO₂ breaksthrough in 2105. In Phase 2, the CO₂ injected into the fifth and sixthlayers rises to the fourth layer and reacts with the water to form CO₂hydrate, blocking upward mitigation of CO₂ to the upper layers. The CO₂hydrate formation starts around the injectors and then moves to theproducers. Producer-4 is converted to injector-4 when CO₂ breaks throughin 2202. In Phase 3, the second through fourth layers around theinjector-4 are blocked once the CO₂ is injected. CO₂ can, however, beinjected into the fifth and sixth layers. When the reservoir pressurereaches the reservoir fracture pressure in 2221, the simulation may beterminated. For the aquifer straddling the HSZ, the injected CO₂ reducesinjectivity in the upper layers inside the HSZ and forces the CO₂injection into the lower layers outside the HSZ. The injected CO₂ risesto the upper layers by gravity segregation to form a CO₂ hydrate furtherblocking the rise of CO₂ (FIG. 15 ).

In the simulations, the pore volume excludes volume occupied by thesolid CO₂ hydrate; therefore, the CO₂ and water saturation add up tounity. It can be seen that CO₂ hydrate forms in the fourth layer (FIG.15 ) and free CO₂ stays at the fifth layer.

For Case 3 (aquifer inside of the HSZ), CO₂ hydrate can form in alllayers. CO₂ cannot be injected into the aquifer from the very beginningbecause the CO₂ hydrate formation reduces injectivity. In Phase 1, thefour corner wells are producers with a total water production rate of20,000 t/d (5,000 t/d per well). Water production may reduce thereservoir pressure until 4 MPa is reached after one year (FIG. 16 ).This is the CO₂ hydrate formation pressure corresponding to atemperature of 8.5° C. (Table 1) in the second layer. In Phase 2, waterproducer-1 is converted to CO₂ injector-1 in 2022. CO₂ is injected at arate of 2,000 t/d (0.73 Mtpa) and the total water production rate by thethree producers is limited to 15,000 t/d. The reservoir pressure firstdecreases due to the continuous water production and then slowlyincreases due to CO₂ injection between 2022 and 2027. When the reservoirpressure drops below 4 MPa, which is the CO₂ hydrate phase boundary forthe second layer, no CO₂ hydrate is formed by 2027 (FIG. 18 ). When CO₂starts to break through in water producer-2 and water producer-3, theyare converted to CO₂ injectors in 2027. In Phase 3, the total CO₂injection rate increases to 3,000 t/d for three CO₂ injectors and thewater production rate is 5,000 t/d in producer-4. The reservoir pressurerises slowly until the CO₂ hydrate formation pressure is reached. CO₂hydrate starts to form between 2027 and 2166. The CO₂ hydrate enclosesthe free CO₂ and delays CO₂ breakthrough in water producer-4 until 2166.In Phase 4, water producer-4 is converted to CO₂ injector-4 to give fourCO₂ injectors with a total CO₂ injection rate of 4,000 t/d. There is nowater production between 2166 and 2185. As discussed before, the CO₂ andwater reservoir volume shrink during CO₂ hydrate formation. The heatreleased by CO₂ hydrate formation and the continuous CO₂ injectionwithout any production force the reservoir pressure to increase slowlybetween 2166 and 2175. In 2175, there is inadequate water to react withCO₂ to form CO₂ hydrate in the aquifer. Therefore, the pressureincreases rapidly. The lower layers of the aquifer are hotter than theupper layers due to the geothermal gradient. CO₂ hydrate formationbegins to occur in the lower layers and the reservoir pressure increasesdue to CO₂ injection. The percent of PV occupied by CO₂ decreases inFIG. 17 due to the formation of CO₂ hydrate in the lower layers. Whenthe reservoir pressure reaches 5 MPa in 2185, which is the CO₂ hydrateformation pressure corresponding to the temperature of 9.7° C. in thesixth layer, the project is terminated because the CO₂ hydrate blocksall injectivity. The simulation may last 164 years and the cumulativeCO₂ injected is 183 Mt.

A cross-section from injector-2 to injector-4 shows the percent of PVoccupied by CO₂ hydrate (FIG. 18 ). The simulation starts in 2021 whenthe aquifer is fully saturated with water initially. CO₂ hydrate formsfrom the top to the bottom of the aquifer inside the HSZ. In Phase 1,all four wells are water producers to reduce the reservoir pressurebetween 2021 and 2022. In Phase 2, the reservoir pressure decreases to 4MPa, which is the CO₂ hydrate formation pressure corresponding to thetemperature of 8.5° C. in the second layer. No CO₂ hydrate forms between2022 and 2027 in FIG. 18 . In Phase 3, when CO₂ breaks through in waterproducer-2 and water producer-3 in 2027, they are converted to CO₂injectors. At the end of Phase 3, there is more CO₂ hydrate nearinjector-2 than injector-4 (FIG. 18 ). There is more CO₂ hydrate in theupper layers than that in the lower layers because CO₂ travels mostlythrough the upper layers due to gravity segregation. The free CO₂ issurrounded by the CO₂ hydrate and travels slowly to the producers. Ittakes 139 years for CO₂ to break through in Phase 3 instead of fiveyears in Phase 2. In Phase 4, water producer-4 is converted to CO₂injector-4 in 2166. CO₂ hydrate forms from the corner to the center ofthe aquifer. When the reservoir pressure reaches 5 MPa in 2185, which isthe CO₂ hydrate formation pressure corresponding to the temperature of9.7° C. in the sixth layer, the simulation is terminated.

Simulation results for all three cases are given in Table 6. The projectlasts for 60, 200, and 164 years for Cases 1, 2 and 3, respectively. Inthe aquifers straddling the HSZ and inside the HSZ, although formationof CO₂ hydrate reduces the CO₂ injectivity, it delays CO₂ breakthroughand lengthens the project, resulting in more CO₂ being injected. Inorder to manage the reservoir pressure, CO₂ injection and waterproduction are controlled. This is key to achieve adequate CO₂injectivity.

TABLE 6 Summary of simulation results for all three aquifers Aquifertype Aquifer Aquifer Aquifer without straddling inside a HSZ HSZ HSZDuration of project (yr) 60 200 164 Total CO₂ storage in mass (Mt) 61164 183 CO₂ stored as free CO₂ in mass (Mt) 61 88 97 CO₂ stored ashydrated in mass (Mt) 0 76 86 Cumulative water produced (Mt) 84 174 304CO₂ stored as free CO₂ in PV (%) 6 7 11 CO₂ stored as CO₂ hydrate in PV(%) 0 5 10 CO₂ stored in PV (%) 6 12 21 Cumulative CO₂ stored/water 0.730.94 0.60 produced (Mt/Mt)

In the aquifer without a HSZ, the mobility of CO₂ is much higher thanthat of water so CO₂ travels readily from the injector to producer. Oncethe CO₂ breaks through in the producers, they are converted to CO₂injectors to prevent CO₂ recycling. CO₂ injection has to be terminatedwhen the reservoir pressure reaches the fracture pressure to prevent CO₂leakage.

The volume ratio of CO₂ to H₂O to form CO₂ hydrate is 1:2.4 at thereservoir conditions with a hydration number of 6. Therefore, CO₂ storedas the CO₂ hydrate accounts for 30% of total CO₂ hydrate volume. Thetotal CO₂ stored in the aquifer without a HSZ, straddling the HSZ, andinside the HSZ are 61 Mt (6% PV), 164 Mt (12% PV) and 183 Mt (21% PV),respectively. However, the total amount of water produced is 84 Mt, 174Mt and 304 Mt for Cases 1, 2 and 3, respectively (Table 6).

The ratio of CO₂ stored to water produced is shown in FIG. 19 . For Case1, there is CO₂ injection but no water production in Phase 1(2021-2026). Once the water production starts in Phase 2 (2026-2044),the ratio of CO₂ stored to water produced decreases quickly. After twowater producers are converted to CO₂ injectors in Phase 3 (2044-2066),the ratio of CO₂ stored to water produced begins to climb. In Phase 4(2066-2081), CO₂ injection occurs but no water production and the ratioof CO₂ stored to water produced increases rapidly. In total, 61 Mt ofCO₂ is stored and 84 Mt of water is produced giving 0.73 tons of CO₂stored for every ton of water produced (Table 6).

For Case 2, both CO₂ injection and water production starts in Phase 1(2021-2105) and the ratio of CO₂ stored to water produced is constant(see FIG. 19 ). In Phase 2 (2105-2202), two producers are converted toCO₂ injectors and the ratio of CO₂ stored to water produced increases.In 2158, the CO₂ injectivity is constrained by the fracture pressurelimit. The CO₂ injection rate is reduced and is equal to the waterproduction rate; the ratio of CO₂ stored to water produced is almostconstant. In Phase 3 (2202-2221), there is CO₂ injection but no waterproduction. The ratio of CO₂ stored to water produced increases to 0.94when the reservoir fracture pressure is reached.

For Case 3, water production occurs but no CO₂ injection occurs in Phase1 (2021-2022). When CO₂ injection commences in Phase 2 (2022-2027), theratio of CO₂ stored to water produced increases. In Phase 3 (2027-2166),two water producers are converted into CO₂ injectors. The ratio of CO₂stored to water produced continuously increases. In Phase 4 (2166-2185),CO₂ injection occurs but no water production. The ratio of CO₂ stored towater produced increases up to 0.6 at the end of the simulation.

FIG. 20 displays the cumulative CO₂ stored versus cumulative waterproduced. Initially, there is no water production and only CO₂ injectionin Case 1 between 2021 and 2026. Therefore, the starting point of Case 1is not at zero water produced. On the other hand, for Cases 2 and 3, thestarting point is at zero water produced. At the end of all cases, thecurves become vertical because there is CO₂ injection but no waterproduction. Of all the cases, Case 2 includes the highest cumulative CO₂stored to water produced. This is partly because CO₂ density is higherat the reservoir condition in Case 2. Although the CO₂ density is thehighest at initial reservoir conditions in Case 3, the reservoirpressure is reduced to below CO₂ hydrate formation pressure; the CO₂density is therefore reduced.

The ratio of the cumulative amount of CO₂ stored to cumulative waterproduced is 0.73, 0.94 and 0.6 Mt/Mt for Cases 1, 2 and 3, respectively.The CO₂ density in the three cases is 0.65, 0.9 and 0.91 t/m3 at theinitial reservoir pressure and temperature (FIG. 5 ). For Cases 1 and 2,the simulation is terminated when the reservoir pressure reaches thefracture pressure, which is higher than the initial reservoir pressure.This causes a higher CO₂ density. Therefore, the ratio of CO₂ stored towater produced is slightly higher than the CO₂ density at the initialreservoir condition. For Case 3, the reservoir pressure is reduced fromthe initial reservoir pressure of 8.7 MPa to the hydrate formationpressure of 5 MPa at the aquifer bottom. This causes the CO₂ density todrop. Consequently, the ratio of CO₂ stored to water produced is lessthen 0.91, which is the CO₂ specific density at initial reservoirconditions. The ratio of cumulative CO₂ stored to cumulative waterproduced is highly sensitive to the CO₂ density at reservoir conditions.More CO₂ is stored in Cases 2 and 3 than Case 1 due partly because morewater is produced. Additionally, results indicate that more CO₂ can bestored in Case 2 per ton of water produced in the operation. Almost halfof CO₂ stored in Cases 2 and 3 are in the form of hydrate (Table 6),which is immobile and acts as a barrier to post-injection CO₂ movement.

In addition to the total amount of CO₂ stored, the risk of CO₂ leakagefrom the aquifer is also investigated. The permeability of the caprockand underburden ranges from 1×10⁻⁵ md to 1,000 md (Table 7) for allthree aquifers and the aquifer permeability is kept constant at 3,000md. All other parameters are kept the same. The horizontal and verticalpermeability is assumed to be same in the simulation.

TABLE 7 CO₂ leakage simulations Aquifer type Aquifer Aquifer Aquiferwithout straddling inside a HSZ HSZ HSZ Caprock 0.00001-1,0000.00001-1,000 0.00001-1,000 permeability (md) Aquifer 3,000 3,000 3,000permeability (md) Underburden 0.00001-1,000 0.00001-1,000 0.00001-1,000permeability (md)

In Case 1, there is no CO₂ leakage through the caprock when itspermeability is 1×10⁻⁵ md as shown in FIG. 21 . The underburden does notaffect the results due to gravity segregation. When the caprockpermeability changes to 1×10⁻⁴ md, CO₂ starts to leak through thecaprock (FIG. 21 ). Therefore, a caprock permeability of 1×10⁻⁵ md orless is needed to avoid any CO₂ leakage.

For Case 2, FIG. 22 displays the fraction PV occupied by CO₂ hydrate andthe CO₂ saturation in 2221. It can be seen from FIG. 22 that a layer ofhigh CO₂ concentration (close to 100% PV) extends from injector-2 toinjector-4 in layer 4 which blocks the upward migration of CO₂ in layer5 (FIG. 22 ). When the caprock permeability increases to 1,000 md, thereis no CO₂ leakage through the caprock because the CO₂ hydrate in layer 4prevents upward migration of free CO₂ from layer 5. Therefore, CO₂storage in an aquifer straddling HSZ (Case 2) is not limited by thecaprock permeability.

For Case 3, FIG. 23 and FIG. 24 show the PV occupied by CO₂ hydrate andthe CO₂ saturation at different caprock permeabilities in 2185. When thecaprock permeability is 0.1 md, some CO₂ hydrate forms in the caprock(FIG. 23 ) although there is no free CO₂ However, when the caprockpermeability is 1 md, more CO₂ leaks through the caprock (FIG. 24 ). TheCO₂ hydrate occupies 90% PV where the CO₂ hydrate is available while therest of the 10% PV in the grid blocks is filled with water and free CO₂;some grid blocks are filled with half brine and half CO₂ and exclude theCO₂ hydrate PV. Because one mole of CO₂ requires six moles of H₂O toform the CO₂ hydrate, the volume ratio of CO₂ and H₂O is 1:2.4 at thereservoir condition as discussed above. As more and more CO₂ migrates tothe caprock, there is not enough water to react with CO₂ to form CO₂hydrate (FIG. 24 ). There is possibility for the free CO₂ to migratesomewhere else. Therefore, CO₂ storage in Case 3 requires a caprock witha permeability of 0.1 md or less versus 1×10⁻⁵ for an aquifer in Case 1.

It is noted that this disclosure assumes a seawater hydrostatic gradientand a geothermal gradient typical of a tropical region. In polarregions, both are different and a HSZ can exists at shallower waterdepths. In addition, a HSZ can also exist in a permafrost on land. It isfurther noted that enough water is produced for the reservoir pressureto drop below the hydrate formation pressure and CO₂ injection begins assoon as practically feasible.

According to this disclosure, it may be possible to store CO₂ in a HSZin an offshore aquifer wherein over half of the injected CO₂ can beimmobilized as solid CO₂ hydrate. Although some of the injected CO₂ isstored as free CO₂, it is also practically immobilized as its movementis severely restricted due to blockage by the CO₂ hydrate. In orderwords, the relative permeability to free CO₂ is reduced due to theformation of CO₂ hydrate. This is highly advantageous as it preventspost-injection CO₂ migration. Furthermore, by careful management ofreservoir pressure through water production and CO₂ injection, it isfeasible to store a large amount of CO₂ (21% PV) in an aquifer insidethe HSZ. This may have important ramifications for the design of CO₂storage in saline aquifers.

Overall, it is shown that in a tropical region, a CO₂ hydrate stabilityzone exists below the seafloor when the water depth is above 630 meters.Within this HSZ, solid CO₂ hydrate can form and be thermodynamicallystable. It has been previously understood that CO₂ cannot be injectedinto an aquifer in this HSZ because formation of solid CO₂ hydrate willimpair CO₂ injectivity near the wellbore. As disclosed herein, it isshown that it is possible to inject CO₂ into an aquifer in the HSZ bycarefully managing the reservoir pressure. If the pressure of the HSZ isreduced to that below the equilibrium pressure for CO₂ hydrate formationby water production, then CO₂ can be continuously injected. Bymanipulating water production with respect to CO₂ injection, thereservoir pressure can be managed. Reducing or stopping water productionwhile keeping CO₂ injection may allow the reservoir pressure to rise.When the reservoir pressure rises to the equilibrium pressure for CO₂hydrate formation, CO₂ will react with water to form solid CO₂ hydrate.Thus, some of the injected CO₂ will solidify as CO₂ hydrate and beimmobilized. Furthermore, any remaining free CO₂ will also be preventedfrom further migration since it is surrounded by solid CO₂ hydrate. Thismethod of sequestering CO₂ as CO₂ hydrate in the HSZ may havesignificant implications in the geological storage of anthropogenic CO₂in offshore saline aquifers. In the tropical region, aquifers with awater depth less than 630 meters are considered too shallow for theexistence of a HSZ. The situation is different in polar regions, wherethe surface temperature of the water is much lower (2° C.-12° C.). Inthis case, the seawater temperature profile intersects the CO₂ hydratephase boundary at much shallower water depths (FIG. 3 ). Therefore, aHSZ can exist at water depths as shallow as 200 meters.

The followings can be concluded based on the aquifer models analyzed:

1. In tropical waters, a HSZ exists below the seafloor when the waterdepth exceeds 630 meters.

2. It is possible to store CO₂ in an aquifer residing inside the HSZ orstraddling the HSZ through management of reservoir pressure by CO₂injectors and water producers.

3. In an aquifer straddling the HSZ, CO₂ can be injected into the lowerpart of the aquifer below the HSZ. However, injected CO₂ migrates to theHSZ to form CO₂ hydrate which blocks further upward migration of CO₂.

4. In an aquifer inside the HSZ, reduction of reservoir pressure belowthe hydrate formation pressure by water production can allow CO₂ to beinjected.

5. In both cases, hydrate formation delays CO₂ breakthrough andmoderates the increase in reservoir pressure due to volume shrinkagethus allowing substantial amount of CO₂ (12-22% PV) to be stored.Furthermore, over half of the injected CO₂ is stored as immobilizedsolid CO₂ hydrate which also effectively blocks migration of the freeCO₂. This substantially reduces the risk of post-injection CO₂ leakagethrough the caprock.

6. The aforementioned results demonstrate the potential of storing CO₂inside the HSZ in a saline aquifer with the benefit of immobilizing thestored CO₂ due to the formation of solid CO₂ hydrate.

For the purposes of this disclosure, the terms “CO₂ hydrate”, “carbondioxide hydrate”, and “hydrate” may be used interchangeably.

It is noted that a wellbore may be used either as a CO₂ injector or as a“producer” or a “water producer”. It is further noted that an “injector”may generally inject CO₂ to a bottom of a wellbore and into anaquifer/reservoir whereas a “producer” is used to produce water from awellbore and from an aquifer/reservoir. It is further noted that water“production” may refer to the extraction of water out of theaquifer/reservoir using one or more wellbores. Generally, water flowsfrom the aquifer into the producer because the bottomhole pressure islower than the aquifer pressure. Water flows up the producer wellborebecause the surface pressure is lower than the bottomhole pressure.

Nomenclature

HSZ—CO₂ hydrate stability zone

PV—Pore volume, m³

Mt—Million ton

mbsf—Meters below seafloor

σ_(fp)—Fracture pressure gradient, kPa/m

v—Poisson's ratio; 0.25 is assumed for sandstone reservoir, 0.4 forshale

σ_(ob)—Overburden pressure gradient, kPa/m

σ_(p)—Pore pressure gradient, kPa/m

σ_(w)—Seawater pressure gradient, 10.52 kPa/m

h_(w)—Water depth, m

σ_(b)—Rock overburden, 24.88 kPa/m

h_(b)—Buried depth below the seafloor for the sandstone reservoirs, m

V_(g)—Gas molar volume, m³/mole

V_(q)—Water molar volume, m³/mole

V_(h)—Gas hydrate molar volume, m³/mole

A plurality of additional features and feature refinements areapplicable to specific embodiments. These additional features andfeature refinements may be used individually or in any combination. Itis noted that each of the following features discussed may be, but arenot necessary to be, used with any other feature or combination offeatures of any of the embodiments presented herein.

Unless otherwise defined, all technical and scientific terms used hereinhave the same meanings as are commonly understood by one of ordinaryskill in the art to which this disclosure belongs. Although methodssimilar or equivalent to those described herein can be used in thepractice or testing of the present disclosure, suitable methods aredescribed herein.

All publications, patent applications, patents, and other referencesmentioned herein are incorporated by reference in their entirety. Incase of conflict, the patent specification, including definitions, willprevail. In addition, the materials, methods, and examples areillustrative only and not intended to be limiting.

It will be appreciated by persons skilled in the art that the presentdisclosure is not limited to what has been particularly shown anddescribed hereinabove. Rather, the scope of the present disclosure isdefined by the appended claims and includes both combinations andsub-combinations of the various features described hereinabove as wellas variations and modifications thereof, which would occur to personsskilled in the art upon reading the foregoing description.

We claim:
 1. A method for sequestering carbon dioxide, comprising:identifying an offshore aquifer, wherein a majority of the offshoreaquifer is configured as a pressure management reservoir; forming thepressure management reservoir via a plurality of wellbores inside oraround the perimeter of the offshore aquifer, the pressure managementreservoir defined and bound by the plurality of wellbores; assigning atleast one function to each of the plurality of wellbores, wherein the atleast one function comprises carbon dioxide injection into the pressuremanagement reservoir and water production from the pressure managementreservoir; injecting, via at least one of the plurality of wellbores,carbon dioxide into the pressure management reservoir; producing, via atleast one other of the plurality of wellbores, water from the offshoreaquifer; and wherein the production of the water maintains the pressuremanagement reservoir pressure below a reservoir fracture pressure and ahydrate formation pressure.
 2. The method of claim 1, further comprisingstoring the carbon dioxide in the offshore aquifer as carbon dioxidehydrate.
 3. The method of claim 1, further comprising storing frombetween 2% to 80% of a total pore volume of carbon dioxide within thepressure management reservoir.
 4. The method of claim 1, furthercomprising storing from between 2% to 80% of a total pore volume ofcarbon dioxide within the pressure management reservoir.
 5. The methodof claim 1, further comprising storing a total quantity of carbondioxide ranging from 1 million tons to 2600 million tons.
 6. The methodof claim 5, wherein the injecting of carbon dioxide is carried outduring all of the separate, preselected timed phases.
 7. The method ofclaim 1, wherein the injecting of the carbon dioxide and the producingof the water are carried out during separate, preselected timed phases.8. The method of claim 1, wherein at least a portion of the offshoreaquifer is contained within a hydrate stability zone.
 9. The method ofclaim 8, wherein the entirety of the offshore aquifer is containedwithin the hydrate stability zone.
 10. The method of claim 8, whereinthe hydrate stability zone exists at a water depth greater than 630meters.
 11. A for sequestering carbon dioxide, comprising: an offshoreaquifer configured as a pressure management reservoir; a plurality ofwellbores positioned inside or along a perimeter of the offshore aquiferthe pressure management reservoir defined and bound by the plurality ofwellbores; the carbon dioxide configured to be injected into thepressure management reservoir via at least one of the plurality ofwellbores; and water configured to be produced from at least one of theplurality of wellbores drilled into the offshore aquifer; whereinproduction of the water from the offshore aquifer maintains the pressuremanagement reservoir pressure below a pressure management reservoirfracture pressure and a hydrate formation pressure.
 12. The system ofclaim 11, wherein the carbon dioxide is stored in the offshore aquiferas carbon dioxide hydrate.
 13. The system of claim 12, wherein theinjection of the carbon dioxide and the production of the water arecarried out during separate, preselected timed phases.
 14. The system ofclaim 12, wherein carbon dioxide is injected during all of the separate,preselected timed phases.
 15. The system of claim 11, wherein a totalpore volume of carbon dioxide ranges from 2% to 80% within the pressuremanagement reservoir.
 16. The system of claim 11, wherein a total storedquantity of carbon dioxide ranges from 1 million tons to 2600 milliontons.
 17. The system of claim 11, wherein at least a portion of theoffshore aquifer is contained within a hydrate stability zone.
 18. Themethod system of claim 17, wherein the entirety of the offshore aquiferis contained within the hydrate stability zone, or straddling thehydrate stability zone.
 19. The system of claim 17, wherein the hydratestability zone exists at a water depth greater than 630 meters.
 20. Thesystem of claim 17, wherein the hydrate stability zone exists at a waterdepth greater than 200 meters.